In the context of the production of crude oil from underground formations, different methods exist for optimizing the extraction of original oil in place (OOIP).
The method for the primary production of crude oil consists, once the well has been drilled, in recovering the crude oil by migration of the oil from the rock or sand formation towards a well of lower pressure and in then pumping it to the surface via a “producing” well. Primary production is for this reason the least expensive method of extraction. Typically, only from 10 to 15% of OOIP is recovered. Nevertheless, as the oil is pumped, the pressure decreases and the extraction becomes more difficult.
Secondary production methods are then employed when the underground pressure becomes insufficient to displace the remaining oil. The commonest technique, water flooding, uses injection wells which force a drive fluid, composed of large volumes of water under pressure, into the zone comprising the oil. During its migration from the zone to one or more producing well(s), the injected water carries along a portion of the oil which it encounters. At the surface, the oil is separated from the injected water. Water flooding makes it possible to recover an additional 10 to 30% of OOIP.
When water flooding reaches the point where production is no longer profitable, a decision has to be taken: change of oil field or recourse to another operating phase. Use may then be made of an enhanced recovery technique using water flooding in which the water comprises surface-active agents and/or polymers. These polymers are used to increase the viscosity of the drive fluid and to thus improve the flushing of the oil by the drive fluid. For example, it is known to increase the viscosity of the water using viscosifying agents, such as partially hydrolyzed polyacrylamides of high molecular weight. However, these acrylic polymers exhibit an inadequate stability when the drive fluid exhibits a certain amount of divalent ions, as is the case in seawater, for example, and/or at operating temperatures of greater than 80/100° C.
These water-dispersible and/or water-soluble surfactants, on contact with the oil present in the rock or the sand, lower the water/oil interfacial tension to make possible the entrainment of the oil trapped in the constrictions of the pores of the reservoir.
It is thus known to inject a drive fluid which makes it possible both to reduce the water/oil interfacial tension below 1 mN/m and to maintain, under the temperature and salinity conditions of the reservoir, a viscosity of 10 cPs at a shearing of 10 s−1 for a concentration of surfactant of less than 1% by weight, as described in United States of America Patents US 2007/0107897 and US 2007/0142235.
Zwitterionic surfactants and in particular betaines are preferably used due to their stability in brines. The term “zwitterionic” describes surfactants having a permanent positive charge independent of the pH and having a negative charge beyond a certain pH. However, these surfactants can decompose when they are used at temperatures of greater than 80/100° C. in saline oil reservoirs and the drive fluid may then suffer a loss in its viscosifying power.